1. Technical Field
The present invention relates generally to the field of subsurface fluid production and reservoir monitoring.
2. Description of Related Art
In the production phase of oil wells, production is often commingled from several layers or stratum in the formation, these layers may or may not be in pressure or flow communication. In most oil wells, water enters the well and is recovered together with the oil. Furthermore, as the well ages the amount or cut of recovered water generally increases. The ratio of water produced compared to the volume of total liquids produced is referred to as the watercut. Wells are typically produced up to watercuts of 95% and even 98% and then abandoned unless the watercut can be reduced. The size of the water cut produced by the well has a substantial effect on the economics of well operations; it also can be a measure of the recovery factor in water flooded reservoirs. Conventional metering devices are employed to measure the water component or cut of a specific product as it flows through a pipeline. These meters measure the differential flow characteristics of water and other components of the liquid to determine the percentage of water. U.S. Pat. Nos. 7,108,069, 6,782,736, 5,625,293, 5,287,752, 4,873,648 and U.S. Patent Publication Nos. 20070055464 and 20070001028 describe watercut measurement techniques.
During production, it is desirable to measure and monitor the inflow properties of each stratum separately. The inflow properties include parameters such as the total liquid flow rate, watercut, gas-to-oil ratio, and static reservoir pressure. Measurements of these properties have traditionally been performed using production logging tools (PLT) disposed downhole on a cable (e.g., wireline, slickline). However, in many wells this is not possible for a variety of reasons, such as: completion access to the formation limits the running of PLTs on wireline (e.g., highly deviated wells, deposits on the tubing, high flow rate wells, etc.); casing size and apparatus disposed within the casing prohibit running PLTs as there is insufficient space for by-pass tubing; logistics and cost of wireline/slickline intervention prohibits running PLTs. This is the case with sub-sea wells, and can also be an issue on unmanned offshore wellhead jackets. Various techniques have been employed in the oilfield industry to detect and measure the commingled components in well fluids. U.S. Pat. Nos. 7,013,715, 6,810,719, 6,216,532, 6,629,564, 6,860,325, 5,535,632, 5,736,637 and U.S. Patent Publication Nos. 20050268702 and 20040244501 describe multiphase flow measurement techniques.
One approach for measuring fluid flow within the well is with a distributed temperature sensing (DTS) system. DTS systems use fiber-optic technology to accurately determine the position and variation of temperature changes over thousands of individual points along a fiber. The optical fiber acts as both the sensing element and the data-transmission medium. Fiber-optic DTS systems use a laser to send pulses of light through a directional optical coupler and down the fiber. As each laser pulse is sent down the fiber, light is scattered by several mechanisms, including fiber density and composition fluctuations, as well as molecules in the fiber. A portion of this scattered light stays within the fiber and is guided back toward the source, where it is split by the directional coupler to a receiver and analyzed to measure the temperature along the fiber.
With a DTS sensor disposed in the wellbore, temperature is continuously collected and transmitted to the surface using fiber optic technology. At the surface, the data can be transmitted to multiple remote locations as desired with satellite, Internet and cable communications. U.S. Pat. Nos. 7,201,221, 7,040,390, 7,215,416, 7,055,604, 6,588,266 and U.S. Patent Publication Nos. 20060215971 and 20060196660 describe fiber optic-based sensors. DTS sensors are implemented for downhole use by providers such as SENSA™, a Schlumberger Company (information available at www.sensa.org).
In producing petroleum and other useful fluids from production wells, it is generally known to add energy to the fluid column in the wellbore with the objective of initiating and improving production from the well. Such systems are commonly referred to as Artificial-lift (AL) systems. Conventional AL systems use a range of operating principles, including rod pumping, gas lift and electrical submersible pumps (ESP). U.S. Pat. Nos. 7,114,557 and 7,114,572 describe conventional ESP apparatus. ESPs are often used for raising the fluids collected in a well. Typically, production fluids enter a wellbore via perforations made in a well casing adjacent a production formation i.e. a layer/stratum. Fluids contained in the formation collect in the wellbore and may be raised by the AL system to a collection point above the earth's surface. The AL systems can also be used to move the fluid from one zone to another.
A need remains for improved techniques and systems to measure and monitor inflow properties and reservoir parameters, particularly in the production phase of oil wells.